Federal Register / Vol. 72, No. 75 / Thursday, April 19, 2007 / Notices 19757 

MODIFICATION SPECIAL PERMITS—Continued 

Application 

number 

Docket 

number Applicant Regulation(s) affected Nature of special permit thereof 

14172–M .. .................... Pacific Bio-Material Management, 

Inc. d/b/a Pacific Scientific 

Transport, Fresno, CA.

49 CFR 173.196 and 173.199 .... To modify the special permit to authorize 

additional customers outside of the current radius specified in the permit, to allow 

more than two freezers on each dedicated 

transport vehicle and to authorize more 

than seven shipments per year. 

14393–M .. .................... Hamilton Sundstrand, Windsor 

Locks, CT.

49 CFR 173.30(e)(iii), (iv), (v) 

and (vi); 173.307(a)(4)(iv).

To modify the special permit to authorize an 

increase in the maximum size of the cylinders integrated in the cooling unit. 

14396–M .. .................... Matheson Tri-Gas, Parsippany, 

NJ.

49 CFR 173.192(a) ..................... To modify the special permit to authorize an 

additional Division 2.3 material to be 

transported in certain DOT specification 

and non-DOT specification cylinders not 

normally authorized for cargo vessel 

transportation, for export only. 

14418–M .. .................... Department of Defense, Ft. 

Eustis, VA.

49 CFR 172.301; 172.400; 

172.504(a).

To reissue the special permit originally 

issued on an emergency basis for the 

transportation in commerce of a water reactive material in special packaging as 

Unitized Group Ration—Express (UGR–E) 

without being subject to Subchapter C of 

the Hazardous Materials Regulations. 

14447–M .. .................... California Tank Lines, Inc., 

Stockton, CA.

49 CFR 177.834 .......................... To modify the special permit to authorize the 

unloading of DOT Specification MC 330 

and 331 while the hose is still attached. 

14476–M .. .................... BP Products North America, Inc. 

(formerly BP Amoco Oil), 

Texas City, TX.

49 CFR 173.202, 173.203, 

173.312, and 173.213.

To reissue the special permit originally 

issued on an emergency basis for the 

transportation in commerce of certain hazardous materials in non-DOT specification 

heat exchanger pressure vessels and 

heat exchanger tube bundles. 

14488–M .. .................... Sanofi Pasteur, Swiftwater, PA ... 49 CFR 173.24(b)(1) ................... To reissue the special permit originally 

issued on an emergency basis for the 

transportation in commerce of an influenza vaccine in a custom stainless steel 

batch reactor at a constant pressure of 1–

5 psig by use of a cylinder feeding air into 

the reactor. 

[FR Doc. 07–1933 Filed 4–18–07; 8:45 am] 

BILLING CODE 4909–60–M 

DEPARTMENT OF TRANSPORTATION 

Pipeline and Hazardous Materials 

Safety Administration 

[Docket No. PHMSA—2006—25803] 

Pipeline Safety: Grant of Waiver; 

Kinder Morgan Louisiana Pipeline, LLC 

AGENCY: Pipeline and Hazardous 

Materials Safety Administration 

(PHMSA); DOT. 

ACTION: Notice; Grant of Waiver. 

SUMMARY: The Pipeline and Hazardous 

Materials Safety Administration 

(PHMSA) is granting Kinder Morgan 

Louisiana Pipeline, LLC (KMLP) a 

waiver of compliance from the Federal 

pipeline safety regulations for a new 

natural gas transmission pipeline. The 

regulations establish the maximum 

stress level and overpressure protection 

limits for natural gas pipelines. 

FOR FURTHER INFORMATION CONTACT: 

Alan Mayberry at (202) 366–5124, or by 

e-mail at Alan.Mayberry@dot.gov or 

Wayne Lemoi at (404) 832–1160, or by 

e-mail at Wayne.Lemoi@dot.gov. 

SUPPLEMENTARY INFORMATION: 

Waiver Request 

Pipeline Operator: Kinder Morgan 

Louisiana Pipeline, LLC (KMLP) 

petitioned PHMSA on August 2, 2006 

for a waiver of compliance with the 

Federal pipeline safety regulations 

limiting the operating stress levels for 

Class 1 locations along the Leg 1 

segment of the KMLP pipeline in 

Louisiana. This waiver would allow 

KMLP to operate a new natural gas 

transmission pipeline at a maximum 

allowable operating pressure (MAOP) 

corresponding to a pipe stress level up 

to 80 percent of the steel pipe’s 

specified minimum yield strength 

(SMYS) in rural areas along the pipeline 

route. SMYS is defined as the level of 

stress where steel transitions from 

elastic to plastic deformation. The 

current maximum SMYS level allowed 

on pipelines in Class 1 locations is 72 

percent according to 49 CFR 192.111. 

Because the proposed operating stress 

level of 80 percent is higher than the 

upper limit of the required overpressure 

protection under existing regulations 

(i.e., 10 percent over MAOP or 75 

percent SMYS), KMLP proposes 

increasing the overpressure protection 

limit to 104 percent of the pipeline 

MAOP or 83 percent SMYS. The 

pipeline MAOP will be 1,440 psig. 

Public Notice 

On November 22, 2006 PHMSA 

published notice of this waiver request 

in the Federal Register (71 FR 67704) 

inviting interested persons to comment 

on the request. We did not receive any 

comments for or against this waiver 

request as a result of this notice. We also 

requested and received supplemental 

information from KMLP. The waiver 

request, Federal Register notice, 

supplemental information from KMLP, 

and all other pertinent documents are 


cprice-sewell on PROD1PC66 with NOTICES
19758 Federal Register / Vol. 72, No. 75 / Thursday, April 19, 2007 / Notices 

available for review in the DOT’s 

Document Management System (DMS), 

Docket Number PHMSA–2006–25803. 

Waiver Analysis 

Background 

On January 6, 2006 PHMSA issued a 

meeting notice and a call for papers in 

the Federal Register (71 FR 977) to seek 

public input on raising the MAOP on 

certain natural gas transmission 

pipelines. On March 21, 2006 PHMSA 

conducted a public meeting where 

subject matter experts from across the 

U.S. and other countries presented 

papers describing technical issues and 

experiences with operating pipelines 

above 72 percent SMYS. After receiving 

favorable public responses and 

comments from the meeting, PHMSA 

began developing criteria for the design 

and operation of pipelines above 72 

percent SMYS. 

PHMSA previously issued three 

waivers allowing operators to operate 

natural gas transmission pipelines above 

72 percent SMYS. The waivers were 

granted with conditions that require 

operators to meet certain specified 

safety criteria. The safety criteria were 

developed from information received 

from the public meeting, industry best 

practices and internal research. KMLP 

used information gathered from these 

prior waiver grants along with internal 

procedures to develop its waiver 

petition. 

Waiver Findings 

PHMSA concludes that granting a 

waiver to KMLP is not inconsistent with 

pipeline safety and achieves a level of 

safety equal to or better than a similar 

pipeline designed and operated under 

existing regulations. The analysis 

concluded the following: 

(1) KMLP’s waiver application 

describes actions for the proposed 

pipeline life cycle addressing pipe and 

material quality, construction quality 

control, pre-in service strength testing, 

the Supervisory Control and Data 

Acquisition (SCADA) System, 

operations and maintenance and 

integrity management. The aggregate 

affect of these actions provides for more 

inspections and oversight than would 

occur on a pipeline installed under 

existing regulations. 

(2) The actions proposed in KMLP’s 

waiver application are consistent with 

prior waiver grants. 

(3) The safety criteria contained in 

this waiver grant requires KMLP to more 

closely inspect and monitor this 

pipeline than a similar pipeline 

installed without a waiver. 

Waiver Grant 

PHMSA grants a waiver of 

compliance with §§ 192.111 and 

192.201(a)(2)(i) to Kinder Morgan 

Louisiana Pipeline, LLC for Class 1 

locations along the Leg 1 segment of the 

KMLP pipeline. The Leg 1 segment is a 

137-mile, 42-inch pipeline, originating 

at the Sabine Pass Liquefied Natural Gas 

(LNG) terminal and extending to 

Evangeline Parish, Louisiana. 

Approximately 92 percent of the Leg 1 

segment is located in Class 1 locations. 

For the purpose of this waiver, the 

waiver area is defined as the pipeline 

right-of-way for the Class 1 locations 

along the entire 137-mile Leg 1 segment 

of the KMLP pipeline. 

Waiver Conditions 

This waiver is granted with the 

following conditions: 

(1) Steel Properties: The skelp/plate 

must be micro alloyed, fine grain, fully 

killed steel with calcium treatment and 

continuous casting. 

(2) Manufacturing Standards: The 

pipe must be manufactured according to 

American Petroleum Institute 

Specification 5L (API 5L), product 

specification level 2 (PSL 2), 

supplementary requirements (SR) for 

maximum operating pressures and 

minimum operating temperatures. Pipe 

carbon equivalents must be at or below 

0.25 percent based on the material 

chemistry parameter (Pcm) formula. 

(3) Fracture Control: API 5L, the 

American Society of Mechanical 

Engineers B31.8 Standard (ASME B31.8) 

and other specifications and standards 

address the steel pipe toughness 

properties needed to resist crack 

initiation, crack propagation and to 

ensure crack arrest during a pipeline 

failure caused by a fracture. KMLP must 

institute an overall fracture control plan 

addressing steel pipe properties 

necessary to resist crack initiation and 

crack propagation and to arrest a 

fracture within eight pipe joints with a 

99 percent occurrence probability or 

within five pipe joints with a 90 percent 

occurrence probability. The plan must 

include acceptable Charpy Impact and 

Drop Weight Tear Test values, which 

are measures of a steel pipeline’s 

toughness and resistance to fracture. 

The fracture control plan, which must 

be submitted to PHMSA Headquarters, 

must be in accordance with API 5L, 

Appendix F and must include the 

following tests: 

(a) SR 5A–Fracture Toughness Testing 

for Shear Area: Test results must 

indicate at least 85 percent minimum 

average shear area for all X–70 heats and 

80 percent minimum shear area for all 

X–80 heats with a minimum result of 80 

percent shear area for any single test 

and must ensure ductile fracture and 

arrest; 

(b) SR 5B–Fracture Toughness Testing 

for Absorbed Energy; and 

(c) SR 6–Fracture Toughness Testing 

by Drop Weight Tear Test: Test results 

must be at least 80 percent of the 

average shear area for all heats with a 

minimum result of 60 percent of the 

shear area for any single test and must 

ensure a ductile fracture. 

The above fracture initiation, 

propagation and arrest plan must 

account for the entire range of pipeline 

operating temperatures, pressures and 

gas compositions planned for the 

pipeline diameter, grade and operating 

stress levels, including maximum 

pressures and minimum temperatures 

for shut-in conditions associated with 

the waiver area. Where the use of stress 

factors, pipe grade, operating 

temperatures and gas composition make 

fracture toughness calculations nonconservative, correction factors must be 

used. If the fracture control plan of the 

pipe in the waiver area does not meet 

these specifications, KMLP must submit 

to PHMSA Headquarters an alternative 

plan providing an acceptable method to 

resist crack initiation, crack propagation 

and to arrest ductile fractures in the 

waiver area. 

(4) Steel Plate Quality Control: The 

steel mill and/or pipe rolling mill must 

incorporate a comprehensive plate/coil 

mill and pipe mill inspection program 

to check for defects and inclusions that 

could affect the pipe quality. This 

program must include a plate (body and 

all ends) ultrasonic testing (UT) 

inspection program to check for 

imperfections such as laminations. An 

inspection protocol for centerline 

segregation evaluation using a test 

method referred to as slab macroetching must be employed to check for 

inclusions that may form as the steel 

plate cools after it has been cast. A 

minimum of one macro-etch test must 

be performed from the first heat 

(manufacturing run) of each sequence 

(approximately 4 heats) and graded on 

the Mannesmann scale or equivalent. 

Test results with a Mannesmann scale 

rating of one or two out of a possible 

five are acceptable. 

(5) Pipe Seam Quality Control: A 

quality assurance program must be 

instituted for pipe weld seams. The pipe 

weld seam tests must meet the 

minimum requirements for tensile 

strength in API 5L for the appropriate 

pipe grade properties. A pipe weld seam 

hardness test using the Vickers hardness 

testing of a cross-section from the weld 

seam must be performed on one length 


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of pipe from each heat. The weld seam 

and heat affected zone hardness must be 

a maximum of 280 Vickers hardness. 

The hardness tests must include a 

minimum of three readings for each heat 

affected zone, three readings in the weld 

metal and two readings in each section 

of pipe base metal for a total of 13 

readings. The pipe weld seam must be 

100 percent UT inspected after 

expansion and hydrostatic testing per 

APL 5L. 

(6) Puncture Resistance: Steel pipe 

must be puncture resistant to 65 tons. 

Puncture resistance will be calculated 

based on industry established 

calculations such as the Pipeline 

Research Council International’s 

‘‘Reliability Based Prevention of 

Mechanical Damage to Pipelines’’

calculation method. 

(7) Mill Hydrostatic Test: The pipe 

must be subjected to a mill hydrostatic 

test pressure of 95 percent SMYS or 

greater for 10 seconds. 

(8) Pipe Coating: The application of a 

corrosion resistant coating to the steel 

pipe must be subject to a coating 

application quality control program. 

The program must address pipe surface 

cleanliness standards, blast cleaning, 

application temperature control, 

adhesion, cathodic disbondment, 

moisture permeation, bending, 

minimum coating thickness, coating 

imperfections and coating repair. 

(9) Field Coating: A field girth weld 

joint coating application specification 

and quality standards to ensure pipe 

surface cleanliness, application 

temperature control, adhesion quality, 

cathodic disbondment, moisture 

permeation, bending, minimum coating 

thickness, holiday detection and repair 

quality must be implemented in field 

conditions. Field joint coatings must be 

non-shielding to cathodic protection 

(CP). Field coating applicators must use 

valid coating procedures and be trained 

to use these procedures. 

(10) Coatings for Trenchless 

Installation: Coatings used for 

directional bore, slick bore and other 

trenchless installation methods must 

resist abrasions and other damages that 

may occur due to rocks and other 

obstructions encountered in this 

installation technique. 

(11) Bends Quality: Certification 

records of factory induction bends and/ 

or factory weld bends must be obtained 

and retained. All bends, flanges and 

fittings must have carbon equivalents 

(CE) below 0.42 or a pre-heat procedure 

prior to welding for CE above 0.42. 

(12) Fittings: All pressure rated 

fittings and components (including 

flanges, valves, gaskets, pressure vessels 

and compressors) must be rated for a 

pressure rating commensurate with the 

MAOP and class location of the 

pipeline. Designed fittings (including 

tees, elbows and caps) must have the 

same design factors as the adjacent pipe 

class location. 

(13) Design Factor—Stations: 

Compressor and meter stations must be 

designed using a design factor of 0.50 in 

accordance with § 192.111. 

(14) Temperature Control: The 

compressor station discharge 

temperature must not exceed 120° 

Fahrenheit or a temperature below the 

maximum long-term operating 

temperature for the pipe coating. 

(15) Overpressure Protection Control: 

Mainline pipeline overpressure 

protection must not exceed 104 percent 

MAOP. 

(16) Welding Procedures: The 

appropriate PHMSA regional office 

must be notified within 14 days of the 

beginning of welding procedure 

qualification activities. Automated or 

manual welding procedure 

documentation must be submitted to the 

same PHMSA regional office. 

(17) Depth of Cover: The soil cover 

must be a minimum of 36 inches in all 

areas. In areas where threats from chisel 

plowing or other activities are threats to 

the pipeline, the top of the pipeline 

must be installed at least one foot below 

the deepest penetration above the 

pipeline. If a routine patrol or other 

observed conditions indicate the 

possible loss of cover over the pipeline, 

KMLP must perform a depth of cover 

study and replace cover as necessary to 

meet the minimum depth of cover 

requirements specified herein. 

(18) Construction Quality: A 

construction quality assurance plan to 

ensure quality standards and controls 

must be maintained throughout the 

construction phase for inspection, pipe 

hauling and stringing, field bending, 

welding, non-destructive examination 

(NDE) of girth welds, field joint coating, 

pipeline coating integrity tests, lowering 

of the pipeline in the ditch, padding 

materials to protect the pipeline, 

backfilling, alternating current (AC) 

interference mitigation and CP systems. 

All girth welds must be nondestructively examined (NDE) by 

radiography or alternative means. The 

NDE examiner must have all required 

certifications which must be current. 

(19) Interference Currents Control: 

Control of induced AC from parallel 

electric transmission lines and other 

interference issues that may affect the 

pipeline must be incorporated into the 

design of the pipeline and addressed 

during the construction phase. Issues 

identified and not originally addressed 

in the design phase must be brought to 

PHMSA Headquarters’ attention. An 

induced AC program to protect the 

pipeline from corrosion caused by stray 

currents must be in place within six 

months after placing the pipeline in 

service. 

(20) Test Level: The pre-in service 

hydrostatic test pressure on 0.8 

designed Class 1 location pipe must be 

equal to or greater than 125 percent of 

the MAOP and produce a hoop stress of 

at least 100 percent SMYS. 

(21) Assessment of Test Failures: Any 

pipe failure occurring during the pre-in 

service hydrostatic test must undergo a 

root cause failure analysis to include a 

metallurgical examination of the failed 

pipe. The results of this examination 

must preclude a systemic pipeline 

material issue and the results must be 

reported to PHMSA Headquarters and 

the appropriate PHMSA regional office. 

(22) SCADA System Capabilities: A 

SCADA system to provide remote 

monitoring and control of the entire 

pipeline system must be employed. 

(23) SCADA Procedures: A detailed 

procedure for establishing and 

maintaining accurate SCADA set points 

must be established to ensure the 

pipeline operates within acceptable 

design limits at all times. 

(24) Mainline Valve Control: Mainline 

valves located on either side of a 

pipeline segment containing a High 

Consequence Area (HCA) where 

personnel response time to the valve 

exceeds one hour must be remotely 

controlled by the SCADA system. The 

SCADA system must be capable of 

opening and closing the valve and 

monitoring the valve position, upstream 

pressure and downstream pressure. As 

an alternative, a leak detection system 

for mainline valve control is acceptable. 

(25) Leak Reporting: KMLP must 

notify the appropriate PHMSA regional 

office within 24 hours of any nonreportable leaks occurring on the 

pipeline. 

(26) Annual Reporting: Following 

approval of the waiver, KMLP must 

annually report the following: 

(a) The results of any in-line 

inspection (ILI) and the results of any 

direct assessment performed within the 

waiver area during the previous year; 

(b) Any new integrity threats 

identified within the waiver area during 

the previous year; 

(c) Any encroachment in the waiver 

area, including the number of new 

residences or public gathering areas; 

(d) Any class or HCA changes in the 

waiver area during the previous year; 

(e) Any reportable incidents 

associated with the waiver area that 

occurred during the previous year; 


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(f) Any leaks on the pipeline in the 

waiver area that occurred during the 

previous year; 

(g) A list of all repairs on the pipeline 

in the waiver area made during the 

previous year; 

(h) On-going damage prevention 

initiatives on the pipeline in the waiver 

area and a discussion of their success or 

failure; 

(i) Any changes in procedures used to 

assess and/or monitor the pipeline 

operating under this waiver; and 

(j) Any company mergers, 

acquisitions, transfers of assets, or other 

events affecting the regulatory 

responsibility of the company operating 

the pipeline to which this waiver 

applies. 

(27) Pipeline Inspection: The pipeline 

must be capable of passing ILI tools. All 

headers and other segments covered 

under this waiver that do not allow the 

passage of an ILI device must have a 

corrosion mitigation plan. 

(28) Gas Quality Monitoring: Gas 

quality monitoring equipment must be 

installed to permit the operator to 

manage and limit the introduction of 

contaminants and free liquids into the 

pipeline. An acceptable gas quality 

monitoring and mitigation program 

must be instituted to not exceed the 

following limits: 

(a) H2S (0.25 grains per 100 standard 

cubic feet or 4 parts per million, 

maximum); 

(b) CO2 (3 percent maximum); 

(c) H2O (less than or equal to 7 

pounds per million standard cubic feet 

and no free water); and 

(d) Other deleterious constituents that 

may impact the integrity of the pipeline 

must be instituted. 

(29) Gas Quality Control: Filters/ 

separators must be installed at locations 

where gas is received into the pipeline 

where the incoming gas stream quality 

includes potentially deleterious 

constituents to minimize the entry of 

contaminants and to protect the 

integrity of downstream pipeline 

segments. 

(30) Cathodic Protection: The initial 

CP system must be operational within 

12 months of placing the pipeline in 

service. 

(31) Interference Current Surveys: 

Interference surveys must be performed 

within six months of placing the 

pipeline in service to ensure compliance 

with applicable NACE International 

Standard Recommended Practices 0169 

and 0177 (NACE RP 0169 and NACE RP 

0177) for interference current levels. If 

interference currents are found, KMLP 

will determine if there have been any 

adverse effects to the pipeline and 

mitigate the effects as necessary. KMLP 

will report to PHMSA the results of any 

negative finding and the associated 

mitigative efforts. 

(32) Corrosion Surveys: Corrosion 

surveys of the affected pipeline must be 

completed within six months of placing 

the respective CP system(s) in operation 

to ensure adequate external corrosion 

protection per NACE RP 0169. The 

survey must also address the proper 

number and location of CP test stations 

as well as AC interference mitigation 

and AC grounding programs per NACE 

RP 0177. 

(33) Verification of Cathodic 

Protection: An interrupted close interval 

survey (CIS) must be performed in 

concert with ILI for all HCA pipeline 

mileage in accordance with 49 CFR 192 

Subpart O reassessment intervals. At 

least one CP test station must be located 

within each HCA with a maximum 

spacing between test stations of one-half 

mile within an HCA. If any annual test 

station reading fails to meet 49 CFR 192 

Subpart I requirements, remedial 

actions must occur within six months. 

Remedial actions must include a CIS on 

each side of the affected test station and 

all modifications to the CP system 

necessary to ensure adequate external 

corrosion control. 

(34) Pipeline Markers: KMLP must 

employ line-of-sight markings on the 

pipeline in the waiver area except in 

agricultural areas or large water 

crossings such as lakes where line of 

sight signage is not practical. The 

marking of pipelines is also subject to 

Federal Energy Regulatory Commission 

orders or environmental permits and 

local restrictions. 

(35) Pipeline Patrolling: Pipeline 

patrolling must be conducted at least 

monthly to inspect for excavation 

activities, ground movement, wash-outs, 

leakage or other activities and 

conditions affecting the safe operation 

of the pipeline. 

(36) Monitoring of Ground Movement: 

An effective monitoring/mitigation plan 

must be in place to monitor for and 

mitigate issues of unstable soil and 

ground movement. 

(37) Review of Risk Assessment 

Calculations: A copy of the C–FER 

PIRAMID risk analysis report regarding 

the pipe subject to this waiver must be 

submitted to PHMSA Headquarters. 

(38) Initial ILI: KMLP must perform a 

baseline ILI in association with the 

construction of the pipeline using a 

high-resolution Magnetic Flux Leakage 

(MFL) tool to be completed within three 

years of placing the pipeline in service. 

KMLP must also run a geometry tool 

after the backfill of the pipeline and 

after the dewatering from the 

hydrostatic strength test but not later 

than six months after placing the 

pipeline in service. 

(39) Future ILI: A second highresolution MFL inspection must be 

performed and completed on the pipe 

subject to this waiver within the first 

reassessment interval required by 49 

CFR Subpart O, regardless of HCA 

classification. Future ILI must be 

performed on a frequency consistent 

with Subpart O for the entire pipeline 

covered by this waiver. 

(40) Direct Assessment Plan: Headers, 

mainline valve bypasses and other 

sections covered by this waiver that 

cannot accommodate ILI tools must be 

part of a Direct Assessment (DA) plan or 

other acceptable integrity monitoring 

method. 

(41) Initial CIS: A CIS must be 

performed on the pipeline within two 

years of the pipeline in-service date. 

The CIS results must be integrated with 

the baseline ILI to determine whether 

further action is needed. 

(42) Damage Prevention Program: The 

Common Ground Alliance’s damage 

prevention best practices must be 

incorporated into the KMLP damage 

prevention program. 

(43) Class 2 and 3 Pipe: Pipe installed 

in Class 2 and Class 3 locations must 

use stress factors of 0.60 and 0.50 as 

required in § 192.111. Pipe in road and 

railroad crossings must meet the 

requirements of § 192.111. Future class 

changes must meet the requirements of 

§§ 192.609 and 192.611. 

(44) Anomaly Evaluation and Repair: 

Anomaly evaluations and repairs must 

be performed based upon the following: 

(a) Anomaly Response Time 

—Any waiver area anomaly with a 

failure pressure ratio (FPR) equal to 

or less than 1.1 must be treated as 

an ‘‘immediate repair condition’’

per 49 CFR 192, Subpart O. 

—Any waiver area anomaly with a 

FPR equal to or less than 1.25 must 

be repaired within 12 months. 

(b) Anomaly Repair Criteria 

—All other pipe segments with 

anomalies not repaired must be 

reassessed according to Subpart O 

and ASME B31.8S requirements 

and class location factor. Each 

anomaly not repaired, as an 

immediate repair, must have a 

corrosion growth rate and ILI tool 

tolerance assigned to it per the Gas 

Integrity Management Program 

(IMP) to determine the maximum 

re-inspection interval. 

—KMLP must confirm the remaining 

strength (R–STRENG) effective area 

method, R–STRENG–0.85dL, and 

ASME B31G assessment methods 

are valid for the pipe diameter, wall 

thickness, grade, operating 


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1Suffolk intends to engage an existing short line 

railroad to provide service over the line and notes 

that such carrier will file a notice of exemption for 

Board authority before commencing operations. 

pressure, operating stress level and 

operating temperature. KMLP must 

also use the most conservative 

method until confirmation of the 

proper method is made to PHMSA 

Headquarters. 

—Dents in the pipe in the waiver area 

must be evaluated and repaired per 

49 CFR 192.309(b) for initial ILI and 

per 49 CFR 192.933(d) for future 

ILI. 

(45) Preliminary Report: A 

preliminary report describing the 

results, completion dates and status of 

the waiver conditions must be 

completed for the pipeline and 

submitted to PHMSA Headquarters and 

the appropriate PHMSA regional office 

prior to commencing construction of the 

pipeline. 

(46) Completion Report: A completion 

report describing the results, completion 

dates and status of the outstanding 

waiver conditions must be submitted to 

PHMSA Headquarters and the 

appropriate regional office within 180 

days after completion of the pipeline. 

(47) ILI Reports: A report must be 

submitted for the pipeline after the 

baseline ILI (MFL and Geometry) run 

has been performed with assessment 

and integration of the results. A report 

must also be submitted upon 

completion of the second ILI run. These 

reports must be submitted to PHMSA 

Headquarters and the appropriate 

PHMSA regional office. 

(48) Potential Impact Radius 

Calculation Updates: If the pipeline 

operating pressures and gas quality are 

determined to be outside the parameters 

of the C–FER Study, a revised study 

with the updated parameters must be 

incorporated into the IMP. 

Waiver Limitations 

Should KMLP fail to comply with any 

conditions of the wavier, or should 

PHMSA determine this waiver is no 

longer appropriate or that the waiver is 

inconsistent with pipeline safety, 

PHMSA may revoke this waiver and 

require KMLP to comply with regulatory 

requirements of §§ 192.111 and 

192.201(a)(2)(i). 

Authority: 49 U.S.C. 60118(c)(1) and 49 

CFR 1.53. 

Issued in Washington, DC on April 13, 

2007. 

Jeffrey D. Wiese, 

Acting Associate Administrator for Pipeline 

Safety. 

[FR Doc. E7–7414 Filed 4–18–07; 8:45 am] 

BILLING CODE 4910–60–P 

DEPARTMENT OF TRANSPORTATION 

Surface Transportation Board 

[STB Finance Docket No. 35014] 

Suffolk & Southern Rail Road LLC—

Sublease and Operation Exemption—

Brookhaven Rail Terminal 

Suffolk & Southern Rail Road LLC 

(Suffolk), a noncarrier, has filed a 

verified notice of exemption under 49 

CFR 1150.31 to sublease from Custom 

Recycling LLC (Custom), a noncarrier, 

and to operate 1,280 feet of rail line 

located at the Brookhaven Rail Terminal 

at Yaphank, Suffolk County, NY. There 

are no mileposts on the line. Custom 

currently leases the line from Nicolia 

Realty LLC, also a noncarrier and owner 

of the line. As a result of this 

transaction, Suffolk will provide 

common carrier service over this line of 

railroad, which currently is being served 

as industry trackage by the New York & 

Atlantic Railway, a Class III rail carrier.1

Suffolk certifies that its projected 

annual revenues as a result of this 

transaction will not exceed those that 

would qualify it as a Class III rail carrier 

and will not exceed $5 million. 

The earliest this transaction may be 

consummated is the May 3, 2007 

effective date of the exemption (30 days 

after the exemption was filed). 

If the verified notice contains false or 

misleading information, the exemption 

is void ab initio. Petitions to revoke the 

exemption under 49 U.S.C. 10502(d) 

may be filed at any time. The filing of 

a petition to revoke will not 

automatically stay the effectiveness of 

the exemption. Petitions for stay must 

be filed no later than April 26, 2007 (at 

least 7 days before the exemption 

becomes effective). 

An original and 10 copies of all 

pleadings, referring to STB Finance 

Docket No. 35014, must be filed with 

the Surface Transportation Board, 395 E 

Street, SW., Washington, DC 20423–

0001. In addition, a copy of each 

pleading must be served on John D. 

Heffner, John D. Heffner, PLLC, 1920 N 

Street, NW., Suite 800, Washington, DC 

20036. 

Board decisions and notices are 

available on our Web site at http:// 

www.stb.dot.gov. 

Decided: April 12, 2007. 

By the Board, David M. Konschnik, 

Director, Office of Proceedings. 

Vernon A. Williams, 

Secretary. 

[FR Doc. E7–7430 Filed 4–18–07; 8:45 am] 

BILLING CODE 4915–01–P 

DEPARTMENT OF THE TREASURY 

Office of the Comptroller of the 

Currency 

Agency Information Collection 

Activities: Proposed Information 

Collection; Comment Request 

AGENCY: Office of the Comptroller of the 

Currency (OCC), Treasury. 

ACTION: Notice and request for comment. 

SUMMARY: The OCC, as part of its 

continuing effort to reduce paperwork 

and respondent burden, invites the 

general public and other Federal 

agencies to comment on a proposed 

information collection, as required by 

the Paperwork Reduction Act of 1995. 

An agency may not conduct or sponsor, 

and a respondent is not required to 

respond to, an information collection 

unless it displays a currently valid 

Office of Management and Budget 

(OMB) control number. The OCC is 

soliciting comment concerning a 

proposed information collection titled, 

‘‘Survey of Minority Owned National 

Banks.’’

DATES: Comments must be submitted on 

or before June 18, 2007. 

ADDRESSES: Communications Division, 

Office of the Comptroller of the 

Currency, Public Information Room, 

Mailstop 1–5, Attention: 1557–NEW, 

250 E Street, SW., Washington, DC 

20219. In addition, comments may be 

sent by fax to (202) 874–4448, or by 

electronic mail to 

regs.comments@occ.treas.gov. You can 

inspect and photocopy the comments at 

the OCC’s Public Information Room, 250 

E Street, SW., Washington, DC 20219. 

You can make an appointment to 

inspect the comments by calling (202) 

874–5043. 

Additionally, you should send a copy 

of your comments to OCC Desk Officer, 

1557–NEW, by mail to U.S. Office of 

Management and Budget, 725 17th 

Street, NW., #10235, Washington, DC 

20503, or by fax to (202) 395–6974. 

FOR FURTHER INFORMATION CONTACT: You 

may request additional information or a 

copy of the collection and supporting 

documentation submitted to OMB by 

contacting: Mary Gottlieb or Camille 

Dickerson, (202) 874–5090, Legislative 

and Regulatory Activities Division, 


cprice-sewell on PROD1PC66 with NOTICES